1. Field of the Invention
The present invention relates generally to a method of characterizing the flowpath for fluid injected into a subterranean formation for displacing hydrocarbons and, more particularly, to characterizing the flowpath by injecting a fluid into the formation, producing fluids from the formation, and determining the percentage of injected fluid in produced fluids.
2. Setting of the Invention
Production rate of hydrocarbons decreases during primary production due to reduced fluid pressure within a subterranean formation a hydrocarbons are produced from the formation. Recovery of hydrocarbons can be increased by use of a secondary recovery method. Waterflooding is a frequently used secondary recovery method which involves injecting an aqueous fluid such as brine into the subterranean formation for displacing hydrocarbons through the formation toward a production well. A subterranean formation is evaluated before a waterflood is initiated to determine if hydrocarbon recovery will increase sufficiently to justify the cost of waterflooding.
Any increase in recovery of hydrocarbons due to waterflooding is a function of the primary flowpath for fluid injected into a subterranean formation for displacing hydrocarbons. The primary flowpath for fluid injected into a nonfractured formation is rock matrix. Fluid injected into a nonfractured formation primarily flows through hydrocarbon-containing rock matrix of the formation and displaces hydrocarbons. Permeability, porosity, and wettability of the rock matrix affect its capacity for fluid flow. The primary flowpath of a naturally fractured formation is natural fractures unless proper waterflood design causes injected fluid to flow through the hydrocarbon-containing rock matrix. Knowledge of whether the primary flowpath for fluid injected into a subterranean formation is rock matrix or natural fractures is important for properly designing a waterflood.
Available methods for determining if a subterranean formation is naturally fractured are inadequate for characterizing the flowpath for fluid injected into the formation. Core samples can be collected from the near-wellbore region of the subterranean formation and examined for fractures. The core samples are liable to become artificially fractured as they are collected and incorrectly represent subterranean formation natural fractures. Any fractures in the samples may be representative of natural fractures in the near-wellbore region, but not necessarily representative of the flowpath for fluid injected into the formation for displacing hydrocarbons through the formation.
A wellbore wall can be visually examined for fractures by using a borehole televiewer. Again, only the near-wellbore region is examined. Any fractures viewed are not necessarily representative of the flowpath for fluid injected into the formation for displacing hydrocarbons through the formation.
A need exists for a method of characterizing the flowpath for fluid injected into a subterranean formation for displacing hydrocarbons through the formation.